The Mid-Atlantic grid operator just won a court case to keep
capacity performance rules that hurt clean energy. Will carbon pricing and
market reforms help make up for it?
PJM, the grid operator responsible for delivering
electricity to about 65 million customers from the mid-Atlantic coast to the Great
Lakes, is working on ways to price carbon into its energy markets, and
incorporate subsidized wind and solar power into its mix. It’s also projecting
a future
grid that’s stable despite a rise in wind, solar and demand-side
energy flexibility -- contrary to concerns expressed
by Energy Secretary Rick Perry.
But for green energy advocates, none of that makes up for
the negative effects of PJM’s Capacity Performance rules -- and as of this
week, those rules are sticking around for awhile.
On Tuesday, a three-judge panel of the D.C. Court of
Appeals rejected challenges to the Federal Energy Regulatory
Commission’s approval of new electricity market rules for PJM’s 13-state
region. Known as capacity performance, these rules introduced year-round
requirements, broken into winter and summer seasonal markets, to replace the
summer-peaking-only market that’s been in place for decades.
PJM’s new year-round requirement was partly a response to
the 2014 polar vortex, when record-cold temperatures simultaneously spiked
demand for heating energy and froze up about 22 percent of the generators
available, leading to emergency conditions. They’re also an attempt to
deliver more efficient allocation of resources, potentially adding up to
billions of dollars, according to PJM’s analysis.
But environmental and clean energy groups have argued from
the start that PJM’s new market structure will make it harder for demand
response, wind and solar resources to recognize their value against always-on
resources like natural-gas-fired power plants.
That’s mainly because capacity performance doesn’t actually
split the market into winter and summer blocks, in a way that would allow
programs and technologies that do best in hot weather, such as air conditioning
cycling or rooftop solar PV, to bid separately from winter resources, when cold
temperatures and heating needs drive peak loads.
Instead, it requires participants to virtually aggregate
summer resources with corresponding amounts of winter-focused resources,
through a complicated process that we’ve covered in some detail at GTM
Squared. The problem is, there aren’t enough remote-control water heaters,
thermal energy storage systems, or other forms of winter-focused capacity to
match up with the well-established summer-peaking capacity resources.
The results from PJM’s
Base Residual Auction last month appear to have borne out the green energy
and demand response industries’ concerns. Capacity for the 2020-2021 period
cleared a price of $76.53 per megawatt-day, well below the prices of $80 to
$100 from last
year’s auction. This fact could be taken as a sign that PJM’s new rules are
working, by delivering cheaper capacity for its utilities and consumers.
But the auction also revealed a big
drop in demand response, down 24 percent compared to last year, and in
solar, down more than 60 percent from the year before, Jennifer Chen, attorney
for the Natural Resources Defense Council (NRDC), noted in a Tuesday blog post. “As predicted, many summer resources
seeking complementary winter resources did not find any to pair with,” she
wrote.
PJM did loosen its rules on aggregation for the auction,
which helped somewhat. Still, the number of seasonal resources that could
combine into annual capacity added up to less than 400 megawatts, or two-tenths
of a percent of total procurement, Chen wrote.
PJM’s final implementation of its capacity performance rules
has upset more than environmentalists. The groups challenging FERC’s decision
in court include NRDC, the Sierra Club, the Union of Concerned Scientists,
and the Advanced Energy Management Alliance representing the demand response
industry. But it also includes separate complaints from the American Public
Power Association and National Rural Electric Cooperative Association, both
representing utilities, which argue that the year-round requirements will
increase capacity costs, with unclear future benefits.
Even so, the three judges ruled unanimously to uphold FERC’s
decision to allow PJM to move ahead with the particulars of its implementation
of capacity performance, including the year-round requirement. Chen wrote that
NRDC was “reviewing the decision and our options for undoing these costly
market rules,” including new complaints filed with FERC, seeking a
re-examination of the seasonal capacity issue -- an issue that’s unlikely to
rise to attention anytime soon, given FERC’s
current lack of a quorum.
Measured against these kinds of figures, PJM’s recent work
on integrating state carbon policies into its markets may not offer much of an
upside to clean energy advocates. Last week, PJM published three white papers laying out its approach to the
process, part of a broader effort being driven by FERC to examine the way state
renewable and carbon policies affect the operation of interstate energy
markets, as we've covered at GTM
Squared.
The first white paper looks at how PJM could establish a
regional or sub-regional carbon price to reflect state renewable and climate
change mitigation policies in wholesale market prices. The second looks at a
new approach to how subsidized resources like wind and solar power are treated
as capacity, by expanding the minimum offer price rule, or
MOPR, to these resources.
Finally, the third white paper “does not respond per se to
state subsidy programs,” but instead “examines whether the aforementioned
profound changes to the industry require re-examination of PJM rules that
define when and under what circumstances a generator is eligible to set
marginal prices.” There’s a lot more to unpack on the concept in the white
paper, but its underlying goal is to deal with “an unintended bias in the
energy markets favoring lower-capital-cost resources." That means things
that are cheaper than big power plants, but that may fail to “signal the true,
full cost incurred to meet the marginal increment of load.”
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